Net production was 312.9 Mboe, up 39% from the 225.4 Mboe in the third quarter of fiscal 2014.

Total revenues increased 22% to $20.3 million from $16.6 million in the third quarter of fiscal 2014.

Adjusted EBITDA increased 669% to $33.2 million from $4.3 million in the third quarter of fiscal 2014. Adjusted EBITDA for the quarter included $21.5 million, net of allowance, attributable to the Company's application for a carried forward annual-loss credit with the State of Alaska, lower general and administrative costs, increased net cash receipts on derivative settlements, offset by additional costs related to the Savant acquisition.

The Company has hedged production for 191 MBbls at $97.09 remaining in fiscal 2015, 788 MBbls at $95.36 in fiscal 2016, and 233 MBbs at $93.97 in fiscal 2017. During the three months ended January 31, 2015, Miller recorded a non-cash gain of $39.3 million related to this favorable crude oil derivatives position.

On December 11, 2014, the Company closed on the acquisition of Savant for approximately $6.0 million in cash, and $3.0 million financed through three promissory notes in $1.0 million increments, of which $1.0 million was paid as of January 31, 2015. As a result of this merger, we acquired a 67.5% working interest in the Badami Unit, 100% ownership in certain nearby leases, and certain midstream assets located in the North Slope. ASRC Exploration, LLC owns the remaining 32.5% working interest in the Badami Unit. This acquisition immediately added approximately 600 bopd net to our production.

During the three months ended January 31, 2015, the Company recognized a $149.1 million non-cash impairment charge related to its Redoubt and West McArthur River Unit fields' proved and unproved properties. The proved and unproved properties were written down to their estimated fair value. This impairment was triggered by the decline in crude oil prices and measured using a discounted cash flow model. Additionally, during the three months ended January 31, 2015, we incurred dry hole costs of $5.5 million related to Olson Creek #2 and impaired $35.0 million of unproved properties due to changes in our drilling plans.

On February 10, 2015, the Company received proceeds from Alaska State tax credits totaling $21.2 million. The Company has received a certificate for further Alaska State tax credits totaling an additional $20.6 million and expects to receive the proceeds later this month.

The Company's borrowing base was reduced to $45.0 million. Currently, the Company has approximately $2.2 million in cash, $39.0 million drawn against our $45.0 million borrowing base, and the cash tax credit certificate of approximately $20.6 million that we expect in mid-March. The Company filed an application for a carried forward annual-loss credit of $23.9 million ($21.5 million, net of allowance) in January 2015 and applied for an additional $9.0 million of expenditure and exploration credits in March 2015, both of which we expect to receive in early summer 2015. Upon receipt of the $20.6 million state tax credit, the borrowing base will effectively be reduced to $40.0 million. Upon receipt of the Alaska State tax credit proceeds from the $23.9 million January 2015 application and the $9.0 million March 2015 application, the availability will effectively be reduced to $30.0 million.

On March 9, 2015, the Company's Board of Directors approved the Company's taking the steps needed to change its fiscal year-end to a calendar year. After the filing of its annual report for the fiscal year ending April 30, 2015, the Company expects to file its transitional report and a new annual report for the year ended December 31, 2015.

On March 3, 2015, we announced that we had successfully drilled and completed our first two new gas wells at the North Fork Unit, bringing both onto production. The first productive zone of the first well, NF 24-26, was producing at a rate of greater than 1.7 MMcfd and increasing at approximately 80 Mcfd per day when the Company closed that zone to begin to test the other three zones. Since then, the Company has begun to flow the second productive zone; it is currently producing approximately 120 Mcfd and appears to steadily improve. The Company still has two more zones to flow at NF 24-26. The second well, NF 42-35, is currently producing at a rate of approximately 400 Mcfd and continues to increase as drilling fluids diminish.

On November 20, 2014, the Company completed the sale of substantially all of its Tennessee operating assets.

"Given our need to reduce leverage and our focus on ensuring sufficient liquidity, we plan on further tightening our discipline in terms of both the amount of capital being spent and the risk-profile of the projects on which it is spent," said Carl F. Giesler, Miller Energy's Chief Executive Officer. "Additionally, given continued low oil prices, we expect to remain focused on our North Fork gas field. As we have said before, we are fortunate -- and we believe unique -- as a Company (1) to have more than 80% of our oil production hedged north of $90 per barrel through April 2016, (2) to sell gas under term contracts at more than $6.50 per Mcf and (3) to benefit from cash tax credits for 35% to 65% of our well costs."

"We believe that our lower-capex, North Fork gas-focused plan is a viable path-forward in the continued low oil price environment," added Mr. Giesler. We believe we are positioned to meet fully our obligations to our lenders, to make timely and full dividend payments to our preferred shareholders, as well as to maximize the value of our resource base."

Third Quarter Results

Net production increased by 39%, with 312.9 Mboe in the third quarter of fiscal 2015, compared to 225.4 Mboe for the third quarter of 2014 and 301.1 Mboe for the second quarter of fiscal 2015. The production increase was attributable to new wells being brought online and the acquisition of Savant, as well as improved performance at Redoubt.

Total revenue
increased by 22%, with $20.3 million in the third quarter of fiscal 2015, compared to $16.6 million for the third quarter of 2014 and $24.2 million for the second quarter of fiscal 2015. The increase from the same quarter last year in revenue was primarily due to increased production volumes and the acquisition of North Fork which increased our natural gas sales, offset by declines in crude oil prices.

Lease operating expense increased by 100%, with $8.8 million in the third quarter of fiscal 2015, compared to $4.4 million for the third quarter of 2014 and $9.0 million for the second quarter of fiscal 2015. The increase in operating costs related to changes in inventory, lower of cost or market adjustments to inventory, and higher operating expenses related to the Savant facilities at the Badami Unit.

Transportation costs increased by 14%, with $1.6 million in the third quarter of fiscal 2015, compared to $1.4 million for the third quarter of fiscal 2014 and $0.4 million for the second quarter of fiscal 2015 due to increased production for the comparable periods.

General and administrative costs paid in cash decreased by 37%, with $6.6 million in the third quarter of fiscal 2015, compared to $10.4 million for the second quarter of fiscal 2015 and $6.1 million for the third quarter of fiscal 2014. The decrease from last quarter was mainly related to lower expense related to changes in our management team and non-recurring legal and SOX-related costs.

Depreciation, depletion and amortization expense increased by 156%, with $19.5 million in the third quarter of fiscal 2015, compared to $7.6 million for the third quarter of 2014 and $20.1 million for the second quarter of 2015. The increase in DD&A expense was primarily a result of increased production from both the Cook Inlet and the acquisition of Savant, and changes in the estimated reserves by field.

Adjusted EBITDA increased by 669%, with $33.2 million in the third quarter of fiscal 2015, compared to $4.3 million for the third quarter of 2014 and $9.4 million for the second quarter of fiscal 2015. The increase related to recognition of $21.5 million, net of allowances, of Alaska carried-forward annual loss credits, lower general and administrative costs, increased net cash receipts on derivative settlements, offset by additional costs related to the Savant acquisition.

Loss before income taxes increased by 2,845%, with $155.3 million in the third quarter of fiscal 2015, compared to $5.3 million for the third quarter of 2014 and $285.7 million for the second quarter of 2015. The increase in the loss relates to the non-cash impairment charge of $149.1 million related to our Redoubt Unit and West McArthur River Unit field.

Nine Months Results

Net production increased by 69%, with 918.8 Mboe in the first nine months of fiscal 2015, compared to 543.7 Mboe for the first nine months of 2014. The production increase was mainly attributable to the accretive volumes from the North Fork and Savant acquisitions, as well as improved performance at Redoubt.

Total revenue
for the first nine months of fiscal 2015 was $69.8 million compared with $48.4 million for the first nine months of fiscal 2014, an increase of approximately 44% year-over-year, primarily due to increased production volumes, the acquisition of North Fork which increased our natural gas sales, offset by declines in crude oil prices.

Lease operating expense increased by 60%, with $24.4 million in the first nine months of fiscal 2015, compared to $15.2 million for the first nine months of fiscal 2014. The increase in operating costs was related to increased production, including the effects of the Savant acquisition and lower of cost or market adjustments to inventory.

Transportation costs increased by 37%, with $4.1 million in the first nine months of fiscal 2015, compared to $3.0 million for the first nine months of fiscal 2014 due to increased production for the comparable periods.

General and administrative costs paid in cash increased by 38%, with $22.4 million in the first nine months of fiscal 2015, compared to $16.3 million for the first nine months of fiscal 2014. The increase is due to lower expense related to changes in our management team and non-recurring legal and SOX-related charges.

Depreciation, depletion and amortization expense increased by 153%, with $56.6 million in the first nine months of fiscal 2015, compared to $22.4 million for the first nine months of fiscal 2014. The increase in DD&A expense is primarily a result of increased production and changes in estimated reserve volumes by field.

Adjusted EBITDA increased by 397%, with $56.5 million for the first nine months of fiscal 2015 as compared to adjusted EBITDA of $11.4 million in the first nine months of fiscal 2014. The increase related to recognition of $21.5 million, net of allowances, of Alaska carried-forward annual loss credits and increases in production and results of operations contributed by recent acquisitions.

Loss before income taxes increased 1,626%, with $460.1 million for the first nine months of fiscal 2015, compared to $26.7 million for the first nine months of fiscal 2014. The increase in the loss relates to the non-cash impairment charges of $414.4 million related to the Redoubt Unit and West McArthur River Units fields.

Cash expenditures for capital projects and equipment, excluding acquisitions,
increased 35% with $127.3 million for the first nine months of fiscal 2015, compared to $94.5 million for the first nine months of fiscal 2014. The increase in capital expenditures relates to our increase in drilling activity.

Outlook

Given that low oil prices have persisted into the final quarter of fiscal 2015, we intend to reduce our overall level of capex given our need to ensure sufficient liquidity as well as to reduce our leverage. Capex for the remainder of calendar 2015, including Fiscal 4Q 2015, should be less than $40.0 million gross and $25.0 million net of the related expected State cash tax credits. At our North Fork Unit, we are currently evaluating lower-risk work-over opportunities in addition to two new wells. Additionally, at Redoubt, we plan on drilling a lower-risk sidetrack of RU-7.

Please dial in at least 10 minutes before the call to ensure timely participation. A playback of the call will be available from 12:00 p.m. ET on March 12, 2015 to 11:59 p.m. ET on April 12, 2015. To listen, call 1-877-870-5176 within the United States or 1-858-384-5517 when calling internationally. Please use the replay pin number 7197770.

About Miller Energy Resources

Miller Energy Resources, Inc. is an oil and natural gas production company focused on Alaska. The Company has a substantial acreage, reserve, and resource position in the State, significant midstream and rig infrastructure to support production, and 100% working interest in and operatorship of most of its assets. Miller Energy has two over-arching objectives: first, to be a long-term participant in the State's E&P industry and in responsibly developing Alaska's oil and gas resources; second, as the only public pure-play Alaska E&P, to be a straightforward vehicle for investors to participate in that development. Miller Energy manages its operations from Anchorage with additional administrative offices in the lower 48. The Company's common stock is listed on the NYSE under the symbol MILL. More information on Miller Energy can be found at www.millerenergyresources.com.

Statements Regarding Forward-Looking Information

Certain statements in this press release and elsewhere by Miller Energy Resources¸ Inc. are "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements involve the implied assessment that the resources described can be profitably produced in the future, based on certain estimates and assumptions. Forward-looking statements are based on current expectations, estimates and projections that involve a number of risks, uncertainties and other factors that could cause actual results to differ materially from those anticipated by Miller Energy Resources, Inc. and described in the forward-looking statements. These risks, uncertainties and other factors include, but are not limited to, the potential for Miller to experience additional operating losses; material weaknesses in Miller's internal control over financial reporting and the need to enhance Miller's systems, accounting, controls and reporting performance; potential limitations imposed by debt covenants under Miller's senior credit facilities on Miller's growth and the ability to meet Miller's business objectives; debt costs under Miller's existing senior credit facilities; the ability of Miller's lenders to redetermine the borrowing base under the First Lien RBL; the increased likelihood of such a redetermination in light of recent declines in oil prices, Miller's ability to meet the financial and production covenants contained in the First Lien RBL and/or Second Lien Credit Facility; whether Miller is able to complete or commence its drilling projects within its expected time frame or expected budget; Miller's ability to recover proved undeveloped reserves; the impact that changes in tax law could have on Miller's ability to benefit from tax credits from the State of Alaska and the impact such changes could have on Miller's future plans, Miller's ability to successfully acquire, integrate and exploit new productive assets in the future; in addition, the previously disclosed acquisition of Savant cannot be guaranteed and access to the liquidity needed to close the sale may be harder to obtain than expected, whether Miller can establish production on certain leases in a timely manner before expiration; Miller's ability to complete the work commitments required as terms of its Susitna Basin Exploration Licenses; Miller's experience with horizontal drilling; risks associated with the hedging of commodity prices; Miller's dependence on third party transportation facilities; concentration risk in the market for the oil and natural gas Miller produces in Alaska, the potential inability of Miller to be able to replace its natural gas sales contract with ENSTAR or the risk that pricing in any replacement agreement might not be as favorable, Miller's ability to perform under the terms of its oil and gas leases, and exploration licenses with the Alaska DNR, including meeting the funding or work commitments of those agreements; uncertainties related to deficiencies identified by the SEC in our Form 10-K for 2011; the impact of natural disasters on Miller's Cook Inlet Basin operations; the effect of global market conditions on Miller's ability to obtain reasonable financing and on the prices of Miller's common stock, Series C Preferred Stock and Series D Preferred Stock; limitations placed on Miller with respect to the issuance and/or designation of additional preferred stock; litigation risks; the imprecise nature of Miller's reserve estimates; risks related to drilling dry holes or wells without commercial quantities of hydrocarbons; fluctuating oil and gas prices and the impact on Miller's results from operations; the need to discover or acquire new reserves in the future to avoid declines in production; differences between the present value of cash flows from proved reserves and the market value of those reserves; the existence within the industry of risks that may be uninsurable; the potential for shortages or increases in costs of equipment, services and qualified personnel; strong industry competition; constraints on production and costs of compliance that may arise from current and future environmental, FERC and other statutes, rules and regulations at the state and federal level; the potential to incur substantial penalties and fines if Miller fails to comply with all applicable FERC administered statutes, rules, regulations and orders; new regulation on derivative instruments used by Miller to manage its risk against fluctuating commodity prices; the impact that proposed federal, state, or local regulation regarding hydraulic fracturing could have on Miller; the effect that future environmental legislation could have on various costs; the impact of certain provisions included in the FY2015 U.S. federal budget on certain tax incentives and deductions Miller currently uses; that no dividends may be paid on our common stock for some time; cashless exercise provisions of outstanding warrants; market overhang related to outstanding options, and warrants; the impact of non-cash gains and losses from derivative accounting on future financial results; risks to non-affiliate shareholders arising from the substantial ownership positions of affiliates; the effects of the change of control conversion features of the Series C and Series D Preferred Stock on a potential change of control; the junior ranking of the Series C and Series D Preferred Stock to the Series B Preferred Stock and all of Miller's indebtedness; Miller's ability to pay dividends on the Series C or Series D Preferred Stock; whether Miller's Series C or Series D Preferred Stock is rated; the ability of Miller's Series C or Series D Preferred Stockholders to exercise conversion rights upon a change of control; fluctuations in the market price of our Series C or Series D Preferred Stock; whether Miller issues additional shares of Series C or Series D Preferred Stock or additional series of preferred stock that rank on parity with the Series C and Series D Preferred Stock; the very limited voting rights held by the Series C and Series D Preferred Stockholders; the newness of the Series D Preferred Stock and the limited trading market of the Series C and Series D Preferred Stock; and risks related to the continued listing of the Series C and Series D Preferred Stock on the NYSE. Additional information on these and other factors, which could affect Miller's operations or financial results, are included in Miller Energy Resources, Inc.'s reports on file with United States Securities and Exchange Commission including its Annual Report on Form 10-K, as amended, for the fiscal year ended April 30, 2014. Capitalized terms used above but not defined above are defined in Miller's Annual Report. Miller Energy Resources, Inc.'s actual results could differ materially from those anticipated in these forward- looking statements as a result of a variety of factors, including those discussed in its periodic reports that are filed with the Securities and Exchange Commission and available on its Web site (www.sec.gov). All forward-looking statements attributable to Miller Energy Resources or to persons acting on its behalf are expressly qualified in their entirety by these factors. Investors should not place undue reliance on these forward-looking statements, which speak only as of the date of this press release. We assume no obligation to update forward-looking statements should circumstances or management's estimates or opinions change unless otherwise required under securities law.

MILLER ENERGY RESOURCES, INC.

CONDENSED OPERATING DATA

(Unaudited)

(Dollars in thousands, except per unit and per day data)

Three Months Ended

January 31, 2015

October 31, 2014

January 31, 2014

Net production volumes:

Oil volume - bbls

220,962

207,544

219,422

Natural gas volume - mcf

551,512

561,199

35,727

Total production - boe (1)

312,881

301,078

225,377

Average daily production (bbls/d)

2,402

2,256

2,385

Average daily production (mcf/d)

5,995

6,100

388

Average daily production (boe/d)

3,401

3,273

2,450

Average realized sales prices:

Average realized oil sales price - bbl

$

57.26

$

87.28

$

94.58

Average realized natural gas sales price - per mcf

6.42

6.75

3.39

Average realized sales price - per boe (2)

51.24

68.00

92.16

Lease operating expenses (boe/d)

$

28.14

$

29.77

$

19.57

Transportation costs (boe/d) (3)

5.14

(1.47

)

6.26

Depreciation, depletion and amortization

19,541

20,082

7,642

General and administrative expenses

7,358

17,901

7,587

General and administrative costs paid in cash

6,630

10,359

6,147

Adjusted EBITDA

33,177

9,357

4,317

Loss before income taxes

(155,277

)

(285,653

)

(5,273

)

------- 1 These figures present production on a boe basis in which natural gas is converted to an equivalent barrel of oil based on a 6:1 energy equivalent ratio. This ratio is not reflective of the current price ratio between the two products. 2 These figures present sales on a boe basis in which natural gas is converted to an equivalent barrel of oil based on a 6:1 energy equivalent ratio. This ratio is not reflective of the current price ratio between the two products. 3 The decrease in transportation costs (boe/d) for the three months ended October 31, 2014, relates to a gas transportation refund of $1.7 million from the closing of the Anchor Point Pipeline acquisition. Excluding this refund would have yielded a $4.10 transportation cost per boe/d.

This press release contains non-GAAP financial measures within the meaning of Regulation G and Item 10(e) of Regulation S-K, as promulgated by the SEC. The presentation of this financial information is not intended to be considered in isolation or as a substitute for, or superior to, the financial information prepared and presented in accordance with GAAP, including that in our public filings.

To supplement the Company's condensed consolidated financial statements, which statements are prepared and presented in accordance with GAAP, we use non-GAAP adjusted EBITDA, or adjusted Earnings Before Income Taxes, Depreciation and Amortization, as a measure to evaluate earnings by excluding certain non-cash expenses as set forth in the table below. The Company uses this non-GAAP financial measure for financial and operational decision making and as a means to evaluate period-to-period comparisons. Management believes that this non-GAAP financial measure provides meaningful supplemental information regarding the Company's performance and liquidity. The Company believes that both management and investors benefit from referring to this non-GAAP financial measure in assessing performance and when planning, forecasting and analyzing future periods. This non-GAAP financial measure also facilitates management's internal comparisons to historical performance and liquidity as well as comparisons to competitors' operating results. The Company believes this non-GAAP financial measure is useful to investors both because (1) it allows for greater transparency with respect to key metrics used by management in its financial and operational decision making and (2) it is used by our institutional investors and the analyst community to help them analyze the health of the business.